Wellbores are drilled to locate and produce hydrocarbons. A downhole drilling tool with a bit at the lower end thereof is advanced into the ground to form a wellbore. As the drilling tool is advanced, a drilling mud is pumped from a surface mud pit, through the drilling tool and out through the drill bit to cool the drilling tool and carry away cuttings. The fluid exits the drill bit and flows back up to the surface for recirculation through the tool. The drilling mud is also used to form a mudcake to line the wellbore.
To drill a well that sometimes extends to several thousands of feet, is often challenged with many obstacles like sticking, blow outs, mud losses, caving, key seating, just to name a few. One common undesired and certainly very costly issue faced by the industry when drilling and completing a well is having the pipe (drill pipe, work pipe, casing, tubing, etc) stuck in the well. There are several reasons why a pipe will get stuck in the well: it could be that a drill pipe is stuck in the wellbore due to key seating when the drill bit relatively sharply deviates from the projected course of the well creating a hard turn on the well profile where a relatively rigid string as the drill pipe is can get stuck or wedged; there is also what is commonly known in the industry as differential sticking when the drill pipe removes the filter cake formed around the wellbore exposing a sufficiently permeable formation where the differential pressure between the wellbore and the formation is sufficiently large to get the pipe stuck along the area in contact with the permeable formation as the pressures try to balance itself; the pipe could be simply mechanical stuck by something dropped down the wellbore; as described above the wellbore is drilled by removing and transporting cuttings (pieces of formation cut by the drilling bit to bore the wellbore) to surface, if the transport to surface of the cuttings is insufficient the accumulation of cutting down the wellbore can eventually form a plug (pack-off) and get the pipe stuck; it is not infrequent that the pipe gets stuck due to a malfunctioning equipment, as for example, a packer that wont release or a casing cement job gone wrong where the cement reaches the pipe's annulus. The above examples are just a few of the reasons why a pipe, of any kind, lowered down a wellbore can get stuck with costly consequences. It is for these reasons that a pipe stuck in the wellbore is of great concern for the industry. A practical way to safely assist in the recovery of a stuck pipe will undoubtedly result in great cost savings for the industry.
Furthermore, with the pursuit of ever deeper and more complex reservoirs the issue of stuck pipe becomes more and more provable and exponentially costly. An example of this is the extreme pressure differentials commonly seen in deep water wells, the complexities of drilling close to a salt dome, the increase of drilling extended reach wells or the new downhole tools designed to drill long horizontal wellbores following the ups and downs of a formation not wider than a couple of tens of feet. The reason why we can now go after these widely different portfolio of hard to reach reservoirs lies in technology, new LWD (Logging While Drilling) tools, new ways to communicate to the downhole drilling tools, new downhole motors, new designs of pipes, etc. As the technology evolves so does the cost of the apparatus lowered downhole to be able to reach these complex reservoirs. Not more than a couple of decades ago the drilling string consisted of a drill bit, some drill collars, heavy weight collars, stabilizers and a jar; now a days the cost of the downhole tools trusted with the task of drilling a wellbore can easily reach millions of dollars. Not only have the downhole tools evolved from chunks of metal to hi end computerized equipment, also the drill pipe has seen its share of improvements in order to cope with increasing power consumption of downhole tools and the demand for faster data transfer between the surface and the downhole tools, the modern pipe is evolving to enable the delivery of power and as a conduit for high speed data transfer. Such improvements can be found in U.S. Patent Application Publication No. 2007/0159351 by Madhavan et al. published Jul. 12, 2007 and filed Nov. 28, 2006. The modernization of the drill pipe will increase even further the total cost of equipment lowered in the wellbore.
As briefly described above during the drilling operation, it is desirable to provide communication between the surface and the downhole tool. Wellbore telemetry devices are typically used to allow, for example, power, command and/or communication signals to pass between a surface unit and the downhole tool. These signals are used to control and/or power the operation of the downhole tools and send downhole information to the surface.
Several different types of telemetry systems have been developed to pass signals between the surface unit and the downhole tool. For example, mud pulse telemetry systems use variations in the flow of mud passing from a mud pit to a downhole tool and back to the surface to send decodable signals. Examples of such mud pulse telemetry tools may be found in U.S. Pat. Nos. 5,375,098 and 5,517,464. In addition to mud pulse wellbore telemetry systems, other wellbore telemetry systems may be used to establish the desired communication capabilities. Examples of such systems may include a drill pipe wellbore telemetry system as described in U.S. Pat. No. 6,641,434, an electromagnetic wellbore telemetry system as described in U.S. Pat. No. 5,624,051, and an acoustic wellbore telemetry system as described in PCT Patent Application Publication WO 2004/085796. Other data conveyance or communication devices, such as transceivers coupled to sensors, have also been used to transmit power and/or data. Depending on the wellbore conditions, data transmission rates and other factors, it may be preferable to use certain types of telemetry over the others for certain operations.
In particular, drill pipe telemetry has been used to provide a wired communication link between a surface unit and the downhole tool. The concept of routing a wire in interconnected drill pipe joints has been proposed, for example, in U.S. Pat. No. 4,126,848 by Denison; U.S. Pat. No. 3,957,118 by Barry et al.; and U.S. Pat. No. 3,807,502 by Heilhecker et al.; and in publications such as “Four Different Systems Used for MWD”, W. J. McDonald, The Oil and Gas Journal, pages 115-124, Apr. 3, 1978. A number of more recent patents and publication have focused on the use of current-coupled inductive couplers in wired drill pipe (WDP) as described, for example, in U.S. Pat. Nos. 4,605,268; 2,140,537; 5,052,941; 4,806,928; 4,901,069; 5,531,592; 5,278,550; 5,971,072; 6,866,306 and 6,641,434; Russian Federation published Patent Application No. 2040691; and PCT Application Publication No. WO 90/14497. A number of other patent references have disclosed or suggested particular solutions for data transmission along the axial lengths of downhole conduit or pipe joints, such as U.S. Pat. Nos. 2,000,716; 2,096,359; 4,095,865; 4,722,402; 4,953,636; 6,392,317; 6,799,632 and US Patent Application Publication 2004/0119607; and PCT Application Publication Nos. WO 2004/033847 and WO 02/06716. Some techniques have described a wire positioned in a tube and placed inside a drill collar as shown, for example, in U.S. Pat. No. 4,126,848.
A description of a mechanism that might be used to release a pipe joint is described in the U.S. Pat. No. 4,364,587 issued to Travis L. Samford on Dec. 21, 1982 and herein incorporated by reference. An example of sensors used in the industry to measure strain in a drill pipe assembly, are described in the U.S. Pat. No. 7,316,277 issued to Benjamin Peter Jeffryes on Jan. 8, 2008 and U.S. Pat. No. 4,359,898 issued to Denis R. Tanguy et al. issued on Nov. 23, 1982; both U.S. patents assigned to Schlumberger Technology Corporation and herein incorporated by reference. Similarly a description of a used method for recording and transmitting a measurement done downhole can be found in U.S. Pat. No. 7,556,104 issued to Benjamin Peter Jeffryes on Jul. 7, 2009, assigned to Schlumberger Technology Corporation and herein incorporated by reference. A description of an example of the means used in the industry to circulate a desired fluid to and from the inside of a tubular to the annulus can be found in U.S. Pat. No. 7,004,252 issued to Charles E. Vise Jr on Feb. 28, 2006, assigned to Schlumberger Technology Corporation and herein incorporated by reference. An example of a mechanism used to push a tubular away from a borehole wall can be found in U.S. Patent Application No. US2008/0314587 filed by Christopher del Campo et all, filed on Jun. 21, 2007 published on Dec. 25, 2008; assigned to Schlumberger Technology Corporation and herein incorporated by reference.
As the communication to and from downhole and surface can be easily established by today methods as described above, a novel monitoring and disconnecting instrumented joint can be used to avoid a stuck pipe and in the event the pipe does get stuck, to ultimately disconnect the free portion of the pipe string from the portion of said string that is stuck. A novel approach to circulate at different points of a pipe string through the instrumented tubular joint, the attempt to free the pipe by pushing it away from the borehole wall and ultimately the release when required of a portion of said pipe string will also be disclosed throughout this application.